The invention relates to a thermal drive process for producing oil from a subterranean reservoir. More particularly, it relates to producing oil from a reservoir interval which contains an oil having a relatively high viscosity, at the reservoir temperature, within a rock layer of relatively high absolute permeability.
The present invention is similar to but distinct from that of patent application Ser. No. 801,271, filed May 27, 1977, now U.S. Pat. No. 4,086,964 by R. E. Dilgren, G. J. Hirasaki, H. J. Hill and D. J. Whitten. The pertinent disclosures and prior art discussion of that application (the '271 application) are incorporated herein by cross-reference. The '271 application relates to a steam-foam-aided steam drive process for producing oil. It is applicable to a reservoir which is sufficiently free of stratifications in the absolute permeability of the rocks so that when steam flows through the reservoir it follows a path having a location determined by the effects of gravity and/or the distribution of the oil, rather than a path confined within one or more layers of particularly permeable rocks. In the process of the '271 application, steam is injected so that a steam channel is formed between horizontally separated injection and production locations. Then, a steam foam consisting essentially of steam, noncondensable gas, aqueous liquid and surfactant is flowed through the steam channel. And, the mobility of the steam foam is controlled so that, without plugging the steam channel, the flowing of the foam through the channel causes the rates of oil production and channel expansion to exceed those provided by flowing steam through the channel.
The present invention differs from the '271 application process in utilizing a mobility-controlling hot water foam consisting essentially of a noncondensable gas dispersed within a hot aqueous liquid. In the present foam, the gaseous phase consists essentially of noncondensable gas; as distinguished from the foam used in the process of the '271 application, in which a predominate proportion of the gaseous phase of the foam is steam. As known to those skilled in the art, at a given pressure, the temperature of a foam of noncondensable gas-in-gaseous liquid is less than that of a steam foam, by an amount at least equivalent to the heat of vaporizing the water that became the steam phase. On the other hand, since a foam consisting essentially of noncondensable gas and hot aqueous liquid is substantially free of steam, it can be used at a high pressure--whereas the use of a steam foam is limited to a pressure in the order of 1800 psi and thus to a reservoir at a depth of less than about 4000 feet.
The process of the present invention is also similar to but distinct from the process of patent application Ser. No. 884,308 filed Mar. 7, 1978 by R. E. Dilgren. The '308 application relates to a steam-foam aided, steam-drive oil recovery process that is similar to the process of the '271 application, except for using an unobviously beneficial foaming agent consisting essentially of a mixture of alkyl benzene sulfonates in which the alkyl groups have straight chains averaging near but less than 12 carbon atoms per group which mixture has a steam-foam forming efficiency at least substantially equaling that of a Conoco C-550 slurry of sulfonates (available from Continental Oil Company).
Various ways have been proposed for utilizing aqueous liquids and noncondensable gases, as mixtures or foams that are used, alone or in conjunction with steam, in fluid drive oil recovery processes. For example, U.S. Pat. No. 3,042,114 suggests injecting steam or hot water to form a hot zone and then injecting relatively cool gas, by itself or mixed with water, to advance the hot zone and improve the utilization of the heat stored in the reservoir rocks. U.S. Pat. No. 3,318,379 indicates that it was the plugging effects of foams which kept them from being successful as oil-displacing fluids and suggests injecting a surfactant, displacing it with surfactant-free liquid, and then injecting a foam-forming gas and a drive fluid to avoid plugging near the injector. U.S. Pat. No. 3,342,261 on fracturing a tar sand or oil shale, depleting the fracture walls, plugging the fracture with foam and repeating the procedure, recommends forming the foam in situ because of the difficulty of pumping and injecting a pre-formed foam. U.S. Pat. No. 3,360,045 suggests locating or forming a preferentially permeable streak or zone within a viscous oil reservoir and then injecting a hot noncondensable gas, then steam, then water, with the noncondensable gas being utilized to avoid the plugging that would occur if the steam or hot water were to be continuously injected. U.S. Pat. No. 3,464,491 relates to avoiding an oil-bypassing flow through a thief zone, by injecting a surfactant and then gas to form a flow-directing foam, and teaches that such a surfactant must be one which forms a foam that is unstable in the presence of oil. U.S. Pat. No. 3,477,510 suggests improving a steam and cool water or gas injecting process, such as that of the U.S. Pat. No. 3,042,114, by injecting alternating slugs of gas and water in order to reduce the tendency for the gas to overrun and the water to underrun the fluids in the reservoir. U.S. Pat. No. 3,529,668 on displacing oil with a foam bank, which is formed by injecting a surfactant followed by a gas, teaches that its displacement requires an injection of, specifically, from about 5 to 15 volumes of gas per volume of aqueous liquid. U.S. Pat. No. 3,572,473 suggests injecting steam to form a steam zone, short of causing a breakthrough into a production location, injecting water that is substantially as hot as the steam zone, to fill that zone, and then injecting unheated water to displace oil toward the production location. U.S. Pat. No. 3,908,762 suggests forming a preferentially permeable channel between injection and production locations within a tar sand, flowing through that channel steam mixed with enough gas to avoid the plugging effects of steam alone and then injecting steam or a mixture of steam and aqueous alkali to produce oil while expanding the channel. U.S. Pat. No. 4,068,717 suggests treating a tar sand by forming a fracture and holding the fracture open with an overburden supporting fluid pressure by first injecting steam at a fracture-forming-pressure and then injecting surfactant and more steam to form a relatively viscous steam foam that prevents a high rate of flow while steam is being flowed through the fracture at an overburdensupporting pressure. Canadian Pat. No. 1,004,977 suggests treating a viscous oil reservoir which has a permeability stratification that causes an injected fluid to channel through a preferentially permeable layer, by injecting hot water or steam until it breaks through into a production location, injecting enough foam or other partial plugging agent to occupy most of the flow paths within the preferentially permeable channel, and then injecting unheated water so that it partially bypasses the plugged zone, and increases the rate of oil production by displacing more of the oil which was heated by the prior injection of hot fluid.